The present invention describes an on-stream method for detecting erosion or partial plugging of manifolded nozzles or restriction orifices (RO) in a two phase (gas/liquid) feed system. The method does not require direct mechanical contact between the sensor and liquid material.
Two phase nozzles are important for a variety of applications particularly for the injection of atomized feed in chemical or petroleum processing operations. In many such processes, operability or selectivity improvements result when an atomized hydrocarbon liquid is sprayed in a controlled and measured manner into the reaction zone, particularly when a process catalyst is involved. One example is the process of fluidized catalytic cracking (FCC) of higher boiling petroleum fractions. Typically, a high degree of atomization is achieved by mixing the liquid feed with a gas and injecting the mixture into the process from a feed nozzle designed to produce finely dispersed drops. In catalytic cracking, steam is typically used as the atomizing gas, but any process compatible gas may be used.
The need to control and measure the distribution of the atomized liquid sprayed into a process vessel is normally satisfied by using multiple services or nozzles. Maintaining the proper mixture of liquid to steam for atomization, and ensuring that each nozzle carries a specified liquid or mass flow, enables potential unit operating advantages. One common operating mode is to maintain equal liquid flow in each nozzle. Appropriate atomization is maintained by ensuring proper flow rates to nozzles with carefully designed geometries that are assumed invariant with operations. Most installations which have multiple feed nozzles usually include block valve or restriction orifices on the liquid and gas lines to an individual nozzle; but these controls do not uniquely determine the liquid flow. When nozzles are fed from a common manifold, there is no assurance that the liquid flow through each nozzle is optimized since only the net liquid flow to the total manifold can be readily measured. In contrast, the gas flow to a nozzle is usually determined by a restriction orifice on the gas line which ensures relatively definitive gas distribution to the individual nozzles.
Measuring mass flow of a liquid is not new. There are a variety of flow meters that have been used to measure mass flow. Some of them are mechanical in nature utilizing the force of a moving liquid to turn a wheel or deflect a needle. Such flow meters can only measure mass flow in single phase conditions and are usually restricted to non-fouling liquids. Those flow meters available for the single phase flow common to the petroleum and petrochemical industry tend to be quite costly. The very high temperatures that are maintained to reduce flow viscosity impose yet other complications. Furthermore, the service liquids readily foul and clog the mechanical components of such flow meters.
There are a variety of flow meters known as "vortex flow meters" that utilize vortex wakes proceedings from obstacles placed in the flow to measure the velocity of the flow from the frequency of vortex shedding. Such flow meters are again limited to single phase flow. Again, they require placement of an obstacle in the flow, and hence are again prone to fouling. The temperature range of most systems is narrow due to fundamental restrictions on the sonic transducers required to pick up the sound generated by the obstacle.
There are a variety of acoustic flow meters that utilize ultrasonics to measure flow. A class of such flow meters utilizes an ultrasonic transducer/receiver attached to the pipe containing the moving fluid, and an ultrasonic receiver/transducer attached to the same pipe upstream and/or downstream of each other. The high operating temperature of many petroleum and petrochemical processes, as well as geometrical constraints on the attachment of the acoustic device, make these flow meters expensive and difficult to apply in many petroleum and petrochemical applications. The temperatures often exceed the operating limits of many single phase flow meters.
Measurement of the liquid fraction of a gas/liquid mixture flowing through two phase nozzles is difficult. Usual devices for flow measurement are sensitive only to the velocity of the flow or its pressure and not to mass flow. Hence, such devices are incapable of measuring liquid flow without separate and equally complex measurements of the density of the mixture. Devices that are capable of measuring single phase liquid flow are expensive and are often intrusive since they require the insertion of an orifice or barrier in the flow which can be easily fouled by the liquid portion of the mixture. Since in most petroleum and petrochemical applications, the two phase mixture is maintained at an elevated temperature to achieve a sufficiently low viscosity for flow, there is a temperature limitation on flow measurement devices as well.
Thus most petroleum and petrochemical installations do not meter flows to each feed nozzle because suitable flow meters and control valves are expensive due to the severity of process conditions and pipe geometry limitations. The development of specialized flow meters to meet such stringent conditions would require significant expense and undesired complexity. Moreover, existing techniques do not permit on-line identification of partial plugging or erosion at individual feed nozzles. Current practices do utilize pressure sensors at nozzles to identify conditions that can be attributed to significant plugging.
Although petroleum and petrochemical processing units may demonstrate improved operation with specified liquid distribution and feed atomization from manifolded feed nozzles, only the net liquid flow to the manifold is usually measured or controlled. However, the probability of flow imbalance, erosion, or plugging among feed nozzles is large due to the complex nature of two phase fluid exiting the nozzle. Uncertainties in liquid distribution are compounded by the possibility that the liquid portion of the fluid could be vaporized. The existence of such flow imbalance is usually inferred only by anomalous process conditions or changes in process output yields over an extended period of time. Furthermore, the feed nozzle throat can partially plug or erode leading to significant flow maldistributions and/or poor feed atomization which can remain undetermined until the unit is shut down for maintenance. Similar plugging or eroding can also occur at the steam restriction orifice. There is thus a need for a technique that can measure and monitor erosion or partial plugging at an individual nozzle. Early identification of nozzle throat erosion or plugging enables operational changes to the process. Such changes include mechanical repairs (where possible) and flow redistribution via adjustments in the oil block valve.